The following documents, mentioned in the course of the description hereafter, illustrate the state of the art:                Chiquet O., Broseta D. and Thibeau S., Capillary alteration of shaly caprocks by carbon dioxide, SPE 94183, 14th Europec Conference, Madrid, Spain, 13-16 Jun. 2005;        Hildenbrand, A., Schlömer S., and Krooss B., Gas breakthrough experiments on fine-grained sedimentary rocks, Geofluids Vol. 2, 3-23, 2002;        Monicard R., Caractéristiques des roches réservoir—Analyse des carottes, Paris, France, Éditions Technip, 1981; and        Zweigel P. et al., Towards a methodology for top seal efficacy assessment for underground CO2 storage, 7th International Conference on Greenhouse Gas Control Technologies, Vancouver, 5-9 Sep. 2004.        
A geologic formation capable of keeping fluids (hydrocarbons for oil reservoirs, CO2 or other gases for storage sites, . . . ) consists of a reservoir rock allowing one to collect fluids coming from a source (mother rock or injection) and of an impervious cap rock located above (at the top) of the reservoir and allowing one to prevent migration of the fluids from the reservoir to the surface. This geologic formation is then referred to as geologic trap.
The capacity of a geologic formation to store fluids, such as hydrocarbons or CO2 for example mainly depends on the morphology of the geologic trap and on the petrophysical properties of the rocks that make up the cap layer.
In general terms, the morphology of a geologic trap is evaluated by means of a geologic characterization based on geophysical data (seismic data for example), and also on data from the wells drilled in the zone (logs, cores and drill cuttings analysis, . . . ). If the geologic formation selected is not located in too hilly a zone, this type of study generally allows one to precisely determine the shape and the extent of the geologic trap.
Petrophysical characterization of the cap rocks requires specific laboratory experiments that can be very long considering the low permeability of such media (typically below 10−4 mD). The permeability of a porous medium corresponds to its capacity to allow a fluid (liquid or gas) to flow under the effect of a pressure gradient. Among all the petrophysical properties, it is by far the inlet capillary pressure that plays the most important part in the capacity of cap rocks to maintain the fluids in the reservoir since it controls the allowable maximum storage overpressure at the top of the reservoir. In the literature, the inlet capillary pressure is also referred to as threshold capillary pressure or breakthrough pressure.
What is referred to as inlet capillary pressure is the minimum pressure difference to be imposed between a non-wetting phase and a wetting phase for the non-wetting phase to be able to start saturating the porous medium considered. The inlet capillary pressure is denoted by PcE.
The significance of the value of the inlet capillary pressure is illustrated on the reservoir scale within the scope of CO2 storage: we consider the case of an aquifer wherein CO2 is injected so as to reduce the emissions discharged to the atmosphere. During storage, the injected CO2 whose density is under usual thermodynamic conditions lower than that of the water in place progressively forms a pocket located in the upper part of the reservoir. At the lower boundary of the pocket (water/CO2 interface), the pressures in each one of the water and CO2 phases are equal since the capillary pressure curve of the reservoir rocks does not generally exhibit a high inlet capillary pressure because these rocks have the property of readily accommodating fluids. Each one of the two phases having a different density, the pressure gradient is also different, which leads to the existence of a pressure difference between the two phases as shown in FIG. 1. This pressure difference is directly related to a height h measured above the water/CO2 interface. FIG. 1 illustrates the pressure difference for two heights h1 and h2 of the water/CO2 interface. The abscissas represent pressures P,PCO2 for the CO2 and PW for the pressure in the water phase. The ordinates represent height h above the interface. In the first case, the interface is at a depth point Cl1. At depth point Cx, height h above the interface is h1. The difference between the pressures is PC(h1). In the second case, the interface is at a depth point Cl2. At depth point Cx, height h above the interface is h2.The difference between the pressures is PC(h2). Within the scope of a CO2 storage operation, height h above the interface changes from h2 to h1. FIG. 1 thus shows an increase in the pressure difference imposed on the top with time, within the scope of a CO2 storage operation.
In general terms, we write: PCO2(h)−PW(h)=(ρW−ρCO2)gh=Pc(h) with:
h: the height above the water/CO2 interface
PCO2 (h): the pressure in the CO2 phase for a height h
PW(h): the pressure in the water phase for a height h
ρCO2: density of the CO2 
ρW: density of the water
g: gravity
Pc(h): the capillary pressure corresponding to a height h.
This pressure difference directly corresponds to the notion of capillary pressure. This capillary pressure Pc(h) furthermore controls the value of the saturation for a given height h. Pc(h) increases as a function of h as shown in FIG. 1: the greater h, the higher the CO2 pressure. The maximum capillary pressure in the reservoir is thus reached at the reservoir top (h=H). This value is denoted by PcT=Pc(H). Since capillary continuity is provided at the reservoir/cap rocks interface, the value of the capillary pressure at the top PcT is therefore also imposed on the cap rock. Two cases can then arise:                the capillary pressure at the reservoir top is lower than the inlet capillary pressure (PcT<PcE): the CO2 remains confined;        the capillary pressure at the reservoir top is higher than the inlet capillary pressure (PcT>PcE): the CO2 starts circulating in the cap rock and the water saturation in the cap layer will tend towards the value corresponding to PcT.        
In practice, within the scope of fluid injections in an underground reservoir, it is advisable to take a given margin in relation to the value of the capillary pressure at the reservoir top calculated from H because the injection itself can generate dynamic overpressures that can locally lead to capillary pressures at the top that are higher than the calculated capillary pressure at the top (PcT).
The previous reminder shows how important it is to properly evaluate the value of the inlet capillary pressure of a porous medium, for example within the scope of the storage of fluids, such as hydrocarbons, CO2 or other fluids, in geologic traps.
There are various methods for evaluating the inlet capillary pressure PcE of a porous medium for the storage conditions (thermodynamic conditions and nature of the fluids).
There is, for example, a known technique based on the mercury porosimetry method. This method consists in converting a capillary pressure curve obtained by mercury porosimetry for the reservoir conditions by means of the following conversion formula (Monicard, 1981):
            P      c      E        ⁡          (      s      )        =                    P        c        E            ⁡              (        m        )              ⁢                            σ          s                ⁢        cos        ⁢                                  ⁢                  θ          s                                      σ          m                ⁢        cos        ⁢                                  ⁢                  θ          m                    with:
σm: mercury/air interfacial tension=480 mN/m
θm: mercury/air contact angle=140°
σs: interfacial tension for the fluids considered in the reservoir (typically CO2/brine within the scope of CO2 storage)
θs: contact angle for the fluids considered in the reservoir (typically CO2/brine within the scope of CO2 storage)
PcE(s): value of the inlet capillary pressure under storage conditions
PcE(m): value of the inlet capillary pressure for the mercury porosimetry measurement conditions under ambient conditions.
Although this method allows very fast estimation of a value for the inlet capillary pressure under storage conditions, the representativity thereof can be affected because of the uncertainty as regards the wettability phenomena (contact angle θstorage). Since the value of the contact angle is generally not known, it is selected equal to zero, which corresponds to a perfect wettability of the fluid in place. Recent experimental measurements have shown that this hypothesis could turn out to be erroneous in particular in the case of geologic storage of CO2 (Chiquet et al., 2005). This approach can lead to significant errors in the calculation of the inlet capillary pressure.
There is also another approach, referred to as “conventional” approach, whose principle is based on the very definition of the inlet capillary pressure. This method is for example described by Monicard (1981).
During this approach, the sample to be studied is first saturated and placed in a containment cell, which allows one to work under imposed pressure and temperature conditions. The inlet end piece of the cell is then swept so as to bring the non-wetting fluid, such as CO2 for example, for which the inlet capillary pressure is sought, just in contact with the face of the sample. A device allowing one to measure small liquid productions (either by weighing the liquids produced or by direct measurement from a fine capillary tube) is then set at the level of the outlet end piece.
The experiment then consists in increasing the pressure of the non-wetting fluid at the inlet face in successive increasing stages while monitoring the production level of the fluid saturating the sample at the outlet. The value of the inlet capillary pressure of the rock in relation to the two fluids used then corresponds to the imposed pressure for which production start of the fluid in place has been observed.
Although the principle is simple, implementation of this type of experiment is however delicate within the scope of cap rock evaluation, for the following reasons:                Length: the number of stages before the desired threshold is reached can be large since, in many cases, no realistic approximations are available before the experiment is started. On the other hand, the required waiting time for each pressure plateau is generally rather long to allow effective detection of the production at the outlet; and        Accuracy: in the vicinity of the inlet capillary pressure, the non-wetting fluid invasion kinetics is particularly slow because its mobility threshold is then reached, which makes its outlet flow rate extremely low and therefore difficult to detect, all the more so since the rock studied is of low permeability.        
The conventional approach thus leads to very long experiment times and rather to an overestimation of the inlet capillary pressure because of a wrong detection of the mobility threshold.
Another technique is the residual capillary pressure approach. This approach was recently proposed (Hildenbrand, 2002) to provide a faster experimental alternative in relation to the conventional approach. The porous medium test cell is prepared in the same way as for the conventional method, but it is placed between two cells C1 and C2 arranged on either side and containing the non-wetting fluid. A valve initially separates cell C1 from the sample which is however in contact with cell C2. A pressure P1 is initially imposed in C1 and a lower pressure P2 is imposed in C2 by seeing to it that the difference between the two pressures is greater than the estimated value of the capillary pressure sought.
The valve is then opened while recording the evolution of P1 and P2. A progressive decrease, then a stabilization is observed for P1 in the course of time, which corresponds to a circulation of the non-wetting fluid towards C2 through the sample. Similarly, pressure P2 increases, then stabilizes. A residual differential pressure is experimentally observed between the two cells, which is interpreted as the inlet capillary pressure of the rock in relation to the fluids studied. Within the scope of this approach, it is also possible to keep P1 constant and to monitor the evolution of P2 only in the course of time.
This approach aroused a real fad as it was published because of the rapidity thereof and of the ease of interpretation. However, recent work has shown that it is risky to directly interpret the differential pressure measured at the end of the experiment directly in terms of inlet capillary pressure (Zweigel et al., 2005). In fact, during the experiment, the upstream part of the sample undergoes an initial drainage stage during circulation of the wetting fluid, then an imbibition stage as the differential pressure progressively decreases. The measured residual pressure therefore corresponds to a pressure at the end of an imbibition stage and not to a pressure at the start of a drainage stage like the inlet capillary pressure. Now, many experimental findings show that these two pressures are generally not equal, the differential pressure at the end of the imbibition stage being systematically lower than the inlet capillary pressure. Although interpretation of the results of this method a priori affords many advantages, it leads, as it is currently considered, to a systematic underestimation of the inlet capillary pressure value.
In relation to the methods currently used and described above, the method according to the invention allows one to obtain a result rapidly, as regards acquisition of the necessary experimental data as well as their interpretation in terms of inlet capillary pressure.